A theory of evolution for locational signals

Since the Review of Electricity Market Arrangements (REMA) was launched last summer, discussions of electricity market reform have been dominated by the issue of location.  

Locational signals or, in other words, the incentives that influence the decisions of electricity market participants to site and operate at a given geographic location, already exist in our electricity system, but there is broad agreement that they need to be reformed. 

However, opinion has been divided between industry and other key stakeholders over what this reform should look like. 

Anyone who has had even half an eye on REMA will know that the proposal which has provoked the strongest debate is locational marginal pricing (LMP). Its proponents argue that LMP is the reform required to fix existing locational signals, and that its introduction is necessary to achieve an efficient, resilient, cost reflective net-zero electricity system. 

This is a serious claim, as introducing LMP would involve a radical overhaul of existing market arrangements, and modelling exercises have been commissioned to provide supporting evidence and examine in greater detail the likely impacts of a move to an LMP market.  

The most prominent of these exercises, carried out by FTI consulting on behalf of Ofgem, estimated that LMP would bring consumer benefits of £28 billion-£51 billion between 2025 and 2040. An earlier assessment commissioned by National Grid ESO, also from FTI Consulting, reached (perhaps somewhat unsurprisingly) a similarly positive conclusion.  

However, putting aside the fact that even optimistic estimates don’t expect it to be possible to implement LMP before 2030, there are several fundamental flaws to this analysis, as well as the wider case for LMP. 

1. The nature of investment

Firstly, the modelling misunderstands the nature of investment in renewable energy projects and thus uses implausibly optimistic estimates of the impact of a move to LMP on the cost of capital.  

Alternative analysis from Frontier Economics has estimated that introducing LMP could lead to an increase in the cost of capital of 2-3 percentage points. By FTI’s own calculation, an increase of just 2.29 percentage points (well within this range) could wipe out the modelled benefits of LMP. Moreover, the analysis dismisses without proper justification the considerable risk of a potentially disastrous investment hiatus during what would be a lengthy implementation period. Any increase in the cost of capital or investment hiatus would have serious consequences for consumer prices so it is critical that these risks are accurately evaluated when considering a move to LMP. 

2. Ability of renewables projects to re-site

Secondly, supporters of LMP tend to overestimate the ability of renewables projects to re-site in response to locational price signals.  

FTI’s modelling estimates up to a third of wind generation could re-site, as well as significant amounts of solar PV and storage. This fails to properly account for the fact that LMP provides a volatile, unpredictable, short-term operational signal that is nigh-on impossible to invest against, not to mention the fact that there are numerous other factors that have greater influence over siting decisions, such as seabed leasing, planning restrictions and grid availability. 

Instead of encouraging re-siting, by introducing increased uncertainty to the market it is more likely that LMP would introduce a negative investment signal that simply varies by degree across the GB electricity network, making long-term investment decisions risky and prohibitively expensive to finance. 

3. Constraint costs

Thirdly, the base case against which an LMP market is assessed is a hypothetical scenario which does not reflect the positive potential for reform within existing market arrangements. The high constraint costs which are present in this hypothetical scenario (and are the root of much of the modelled business case for LMP) are therefore likely to be significantly exaggerated. 

Indeed, much of the narrative around constraint costs has become misguided. 

Constraint costs have risen to the level they are at today because network build has failed to keep pace with renewables deployment, combined with recent increases in gas prices making it even more costly to turn up gas generation to meet demand in import-constrained areas.  

It is therefore simply incorrect to suggest, as some proponents of LMP have done, that rising constraint costs are the fault of renewables locating in the ‘wrong’ place due to a lack of locational signals.  

In reality, the GB electricity market already contains several strong locational signals. 

Rather than implement a radical reform of the wholesale market, with all the risks which that entails, there are multiple opportunities to improve these signals, both in investment and operational timescales, largely within the current market framework which would be less disruptive, quicker to implement and achieve similar outcomes to the supposed benefits of LMP. 

For example, the Transmission Network Use of System (TNUoS) charging regime already has an extremely strong locational component for generation to the point where Scottish projects are being penalised to the tune of tens of millions of pounds every year relative to projects in southern England. However, the volatility and unpredictability of TNUoS charges undermines their ability to provide a reliable, cost reflective locational investment signal.  

Industry believes that TNUoS should therefore be reformed to provide a stable, transparent, long-term investment signal that accurately reflects the value of generation and demand to the electricity system. Scottish Renewables is already working to bring these reforms to bear through its participation in the TNUoS taskforce. 

Locational signals can also be significantly improved by reforming planning regimes.  

Arguably, the strongest locational signal currently present in the GB electricity system is the de-facto ban of onshore wind in England, albeit there are moves afoot to change that wrongheaded situation.  

Similarly, the fact that grid connection lead times now stretch into the late-2030s  severely disincentivises investment in projects in areas with longer delays.  

To overcome these barriers, strategic network planning, energy system planning and national and local planning regimes must be aligned to net-zero and coordinated so that network infrastructure, low-carbon technologies and system assets are incentivised to locate as the UK’s pathway to net-zero requires. 

There is also significant potential in innovative proposals such as expanding the use of constraint management markets. National Grid ESO, which runs the GB electricity network, is already exploring this through its Local Constraint Market (LCM) pathfinder on the B6 boundary between Scotland and England. However, whilst an important first step, the LCM is still significantly limited in its scope. For example, it only operates in short timescales behind the constraint in one constrained region. If this market could be expanded to operate across longer timescales on both sides of multiple grid constraints, it could potentially offer much of the benefits an LMP market can supposedly deliver in terms of flexibility – without the associated risk and market upheaval.  

Combined with reforms to improve the transparency and efficiency of the Balancing Mechanism this could greatly improve the locational signals delivered to the flexibility assets, such as electricity storage and flexible demand, which will be essential for maintaining the security and operability of a renewables-dominated electricity system.     

A recent paper from Regen - an independent centre of energy expertise with a mission to accelerate the transition to a zero-carbon energy system - covers these proposals in greater detail.  

But given the outline provided above, the ultimate course of action should be clear: evolution, not revolution, is the only approach to electricity market reform that will deliver on REMA objectives whilst avoiding increased risk and a likely investment hiatus that will slow the pace and increase the cost of the clean energy transition.  

Under this approach, incremental reforms to locational signals should be implemented alongside complementary reforms to existing market arrangements, such as the Contracts for Difference mechanism, to provide a comprehensive package of evolutionary reform. 

Risky, revolutionary reforms such as LMP should be ruled out in any form, at the earliest opportunity - the mere fact that LMP is still on the table is already making developers’ conservations with investors and other stakeholders significantly more challenging.  

This will allow the next REMA consultation, scheduled for this autumn, to focus on constructive discussion of the evolutionary, incremental reforms that will safeguard investment, deliver an efficient, resilient decarbonised electricity system, and ensure the UK’s 2050 net-zero target remains within reach. 

• Blog by Andrew MacNish Porter, Senior Policy Manager - Economics and Markets